After hydrocarbons have been removed from the ground, the fluid stream (such as crude oil or natural gas) is transported from place to place via pipelines. It is desirable to know with accuracy the amount of fluid flowing in the stream, and particular accuracy is demanded when the fluid is changing hands, or “custody transfer.” Custody transfer can occur at a fluid fiscal transfer measurement station or skid, which may include key transfer components such as a measurement device or flow meter, a proving device, associated pipes and valves, and electrical controls. Measurement of the fluid stream flowing through the overall delivery pipeline system starts with the flow meter, which may include a turbine meter, a positive displacement meter, an ultrasonic meter, a coriolis meter or a vortex meter.
Flow characteristics of the fluid stream can change during product delivery that can affect accurate measurement of the product being delivered. Typically, changes of pressure, temperature and flow rate are acknowledged by operator intervention. These changes are represented as changes in the flow characteristics, and are normally verified by the operator via the effects of the changes and their effect on the measurement device. Normally, this verification is conducted by proving the meter with a proving device, or prover. A calibrated prover, adjacent the measurement device on the skid and in fluid communication with the measurement device, is sampled and the sampled volumes are compared to the throughput volumes of the measurement device. If there are statistically important differences between the compared volumes, the throughput volume of the measurement device is adjusted to reflect the actual flowing volume as identified by the prover.
The prover has a precisely known volume which is calibrated to known and accepted standards of accuracy, such as those prescribed by the American Petroleum Institute (API) or the internationally accepted ISO standards. The precisely known volume of the prover can be defined as the volume of product between two detector switches that is displaced by the passage of a displacer, such as an elastomeric sphere or a piston. The known volume that is displaced by the prover is compared to the throughput volume of the meter. If the comparison yields a volumetric differential of zero or an acceptable variation therefrom, the flow meter is then said to be accurate within the limits of allowed tolerances. If the volumetric differential exceeds the limits allowed, then evidence is provided indicating that the flow meter may not be accurate. Then, the meter throughput volume can be adjusted to reflect the actual flowing volume as identified by the prover. The adjustment may be made with a meter correction factor.
One type of meter is a pulse output meter, which may include a turbine meter, a positive displacement meter, an ultrasonic meter, a coriolis meter or a vortex meter. By way of example, FIG. 1 illustrates a system 10 for proving a meter 12, such as a turbine meter. A turbine meter, based on turning of a turbine-like structure within the fluid stream 11, generates electrical pulses 15 where each pulse is proportional to a volume, and the rate of pulses proportional to the volumetric flow rate. The meter 12 volume can be related to a prover 20 volume by flowing a displacer in the prover 20. Generally, the displacer is forced first past an upstream detector 16 then a downstream detector 18 in the prover 20. The volume between detectors 16, 18 is a calibrated prover volume. The flowing displacer first actuates or trips the detector 16 such that a start time t16 is indicated to a processor or computer 26. The processor 26 then collects pulses 15 from the meter 12 via signal line 14. The flowing displacer finally trips the detector 18 to indicate a stop time t18 and thereby a series 17 of collected pulses 15 for a single pass of the displacer. The number 17 of pulses 15 generated by the turbine meter 12 during the single displacer pass, in both directions, through the calibrated prover volume is indicative of the volume measured by the meter during the time t16 to time t18. Multiple displacer passes are required to attain the prover volume. By comparing the prover volume to the volume measured by the meter, the meter may be corrected for volume throughput as defined by the prover.
FIG. 2 illustrates another system 50 for proving an ultrasonic flow meter 52, using transit time technology. The system 50 also includes a prover 20 and a processor 26. By ultrasonic it is meant that ultrasonic signals are sent back and forth across the fluid stream 51, and based on various characteristics of the ultrasonic signals a fluid flow may be calculated. Ultrasonic meters generate flow rate data in batches where each batch comprises many sets of ultrasonic signals sent back and forth across the fluid, and thus where each batch spans a period of time (e.g., one second). The flow rate determined by the meter corresponds to an average flow rate over the batch time period rather than a flow rate at a particular point in time.
In a particular embodiment of the prover 20, and with reference to FIG. 3, a piston or compact prover 100 is shown. A piston 102 is reciprocally disposed in a flow tube 104. A pipe 120 communicates a flow 106 from a primary pipeline to an inlet 122 of the flow tube 104. The flow 108 of the fluid forces the piston 102 through the flow tube 104, and the flow eventually exits the flow tube 104 through an outlet 124. The flow tube 104 and the piston 102 may also be connected to other components, such as a spring plenum 116 that may have a biasing spring for a poppet valve in the piston 102. A chamber 118 may also be connected to the flow tube 104 and the piston 102 having optical switches for detecting the position of the piston 102 in the flow tube 104. A hydraulic pump and motor 110 is also shown coupled to the flow line 120 and the plenum 116. A hydraulic reservoir 112, a control valve 114 and a hydraulic pressure line 126 are also shown coupled to the plenum 116. As will be shown below, the piston 102 can be adapted according to the principles taught herein.
In some applications, the fluids flowing in the pipelines (primary pipelines and those of the measurement station) are maintained at low temperatures. As used herein, low temperatures, for example, are generally less than about −50° F., alternatively less than about −60° F., alternatively less than about −220° F., and alternatively less than about −250° F. These low temperatures may also be referred to as very low temperatures or cryogenic temperatures. Examples of fluids maintained at low temperatures include liquid natural gas (LNG), liquefied petroleum gas (LPG) and liquid nitrogen. Low temperatures of the metered fluids cause numerous problems, such as unsuitability of the prover's sensing devices, wear on components such as seals, and reduced lubrication on the flow tube's inner surface for the low temperature fluids, which tend to be non-lubricating. Carbon steel reacts negatively to low temperature product flowing in the pipeline.
To address these problems, meters operating in very low temperatures are proved by indirect proving methods. Generally, indirect proving is accomplished by proving a meter suitable for very low temperature service using a prover that is not rated for very low temperature service. First, a fluid, generally water, is flowed through a proving meter, and the proving meter is proved in the normal way to establish a meter factor for the proving meter. The proving meter is then used on actual flowing low temperature product to obtain the meter factor for the meter measuring the low temperature product. Consequently, the proving meter is calibrated using a fluid unlike the actual product delivered through the meter (at least with regard to density), leading to incorrect results in the actual product meter to be calibrated.
Thus, there is a need for a prover adapted for very low temperatures, at least to increase durability of the prover and to provide direct proving of very low temperature products.